TC Energy Corp (TRP) 2013 Q3 法說會逐字稿

Welcome to the TransCanada Corporation 2013 third quarter results conference call. I would now like to turn the meeting over to Mr David Moneta, Vice President of Investor Relations. Please go ahead, Mr Moneta.

Thanks very much. Good morning, everyone. I would like to welcome you to TransCanada's 2013 third quarter conference call. With me today are -- Russ Girling, President and Chief Executive Officer; Don Marchand, Executive Vice President and Chief Financial Officer; Alex Pourbaix, President of Energy and Oil Pipelines; Karl Johannson, Executive Vice President and President - Natural Gas Pipelines; and Glenn Menuz, Vice President and Controller. Russ and Don will begin today with some opening comments on our financial results and certain other Company developments. Please note that, a slide presentation will accompany their remarks. A copy of the presentation is available on our website at TransCanada.com, it can be found in the Investor section under the heading, Events and Presentations.

Following their prepared remarks, we will turn the call over to the conference coordinator for your questions. During the question-and-answer period, we'll take questions from the investment community first, followed by the media. In order to provide everyone with an equal opportunity to participate, we ask that you limit yourself to two questions. If you have additional questions, please reenter the queue. Also, we ask that you focus your questions on our industry, our corporate strategy, recent developments and key elements of our financial performance. If you have detailed questions relating to some of our smaller operations or your detailed financial models, Lee and I would be pleased to discuss them with you following the call.

Before Russ begins, I would like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TransCanada with Canadian Securities regulators and the US Securities and Exchange Commission. Finally, I would also like to point out that during this presentation, we will refer to measures such as comparable earnings, comparable earnings per share, earnings before interest, taxes, depreciation and amortization or EBITDA and funds generated from operations.

These and certain other comparable measures do not have any standardized meaning under GAAP and are therefore considered to be non-GAAP measures. As a result, they may not be comparable to similar measures presented by other entities. These measures are used to provide you with additional information on TransCanada's operating performance, liquidity and its ability to generate funds to finance its operations. With that, I'll now turn the call over to Russ.

Thank you, David. Good morning everyone. Thank you all very much for joining us this morning. I'm very pleased to report we had a very strong quarter of earnings and cash flow from our diverse portfolio of critical energy infrastructure assets. Comparable earnings in the third quarter of 2013 were 26% higher than during the same period last year. That strong performance was mainly the result of the return to an 8-unit site at Bruce Power, higher Alberta power prices and an increase in New York capacity prices, as well as a higher return on our Canadian Mainline. These positive result however were somewhat offset by continued weak performance in our long-haul US gas pipeline businesses and in our US gas storage businesses.

Our capital program continued to grow in the third quarter. We announced the Energy East project. We now have CAD38 billion of commercially secured projects including -- the Gulf Coast project; Keystone XL; the Keystone Hardisty terminal; the Heartland pipeline and TC terminals project; the initial phase of the Grand Rapids project; the Tamazunchale extension; and the acquisition of the remaining six Ontario solar projects; as well as the ongoing expansion of the NGTL system. Other large scale projects in development include -- the CAD12 billion Energy East project that I mentioned; the Coastal GasLink; and Prince Rupert transmission projects; the West Coast - Topolobampo and Mazatlan pipeline projects in Mexico; and the completion of the Grand Rapids and Northern Courier oil pipeline projects in northern Alberta; and on the energy side, the Napanee generating station in Eastern Ontario.

All of those projects are anchored by long-term contracts or cost of service like arrangements. As a result, we expect those initiatives to generate sustained earnings and cash flow for our shareholders for many years to come. I'll now give you a few highlights of our third quarter earnings before I get into some of the details on those projects. As I said, our three business segments performed well during the third quarter. TransCanada reported net income of CAD481 million or CAD0.68 per share. Comparable earnings for the quarter were CAD447 million or CAD0.63 per share versus the CAD349 million or CAD0.50 per share we earned in Q3 of 2012, which as I said is a 26% increase on a per share basis.

Comparable EBITDA was CAD1.3 billion and funds generated from operations were CAD1 billion. The Board of Directors also declared a quarterly dividend of CAD0.46 per common share for the quarter ending December 31, 2013. So as I said, a good quarter, which reflects the strength and resilience of our diverse portfolio. Don Marchand, our CFO, will provide more details on our financial results in a moment. But before we get to that, I'd like to give you a brief update on how our key projects are progressing.

I'll start with the Energy East project. In August, we informed stakeholders that we'd be moving forward with the 1.1 million barrel per day crude oil pipeline, underpinned by firm binding contracts for over 900,000 barrels per day. The Energy East project will transport oil from Western Canada to Eastern Canadian refineries, but as well export terminals. It is an initiative that will create significant employment opportunities, tax revenue and energy security for all regions of Canada for many decades to come.

With respect to energy security, this project allows Canada to displace unstable oil from foreign suppliers. Not everyone, I'm sure is aware, that Central and Eastern Canada currently import over 700,000 barrels a day of oil to meet their needs. Energy East creates the opportunity for Canada to use and refine its own resources and something that we believe benefits Canadians across this country.

The benefits of Energy East extend beyond energy security. In September, Alex and I were in Fredericton to release an independent report from Deloitte and Touche that highlighted the economic benefits of that CAD12 billion project. They used a statistics Canada modeling process. The report found that Energy East would generate about CAD35 billion in additional gross domestic product for Canada, create more than 10,000 full-time jobs during development and construction and 1,000 more jobs once that pipeline is operational.

Local communities and governments will see further benefits, as Deloitte determined the project will generate an additional CAD10 billion of tax revenue for all level of governments over the lifetime of the project. Energy East will complement our planned Keystone XL pipeline as another tangible way of transporting growing production out of Western Canada to Eastern Canadian refineries, but also US refineries. In the case of Energy East, we'll also be in a position where we can attach energy supplies from Western Canada to global markets. As crude oil production grows in both Canada and the United States, new pipeline infrastructure is required to move that product safely and efficiently. This is what projects like the Keystone XL pipeline and Energy East will do. We intend to file the necessary permits for the project in the first half of 2014.

Now moving over to the US side, in mid-October, we recognized and thanked nearly 5,000 workers in America who helped us build the CAD2.3 billion Gulf Coast project. Construction on that project is now 95% complete. We are preparing for crude oil to begin commercial service later this year. Today, produces do not have access to sufficient pipeline capacity to move their production from Cushing to the large refining markets in the US Gulf Coast. The Gulf Coast project addresses that constraint, allowing US refiners to access lower cost domestic production and avoid paying premiums to foreign oil suppliers. This supports additional refining jobs in Texas and the economic benefits those jobs provide to that state.

As I said, we expect this 700,000 barrel per day pipeline to be operational by the end of the year. In addition, construction of the CAD300 million Houston lateral project is underway, that 76-kilometer project will transport crude oil to Houston refineries and is expected to be completed in 2014. On to Keystone XL, where we continue to focus on the release of the final supplemental environmental impact statement, which is to be issued by the Department of State once its review is complete. That review has now eclipsed the 1,800 day mark since the review began in 2008.

Our base Keystone pipeline system to date has safely delivered about 0.5 billion barrels of oil to refineries in Illinois and Oklahoma, since it started operations in the summer of 2010. The review for that project, which was nearly identical to Keystone XL took approximately 21 months. Once the FEIS is issued, the state department is expected to begin the national interest determination period for Keystone XL, which will lead to a decision on the Presidential Permit. As I've said on multiple occasions, the Keystone XL decision should be based on facts. The facts are that the US consumes 50 million barrels a day of oil each and every day and imports 7 to 8 million barrels a day from places outside of the United States.

Both the US Energy Information Administration and the International Energy Agency predict that America will continue to import millions of barrels of oil each day through and beyond 2040. So what we're really talking about here is choice. A choice made all that more relevant by the recent unrest in the Middle East. The choice is, do Americans want their crude oils from a friendly partner in Canada? Or will they continue to rely on unstable regions. Based on consistent polls since 2011, the majority of Americans continue to support our project and that choice of getting their oil from Canada. The CAD5.4 billion cost estimate will increase depending on the timing of the permit. As of September 30, 2013, we had invested approximately CAD2 billion into that project.

Now back in Canada, our crude oil strategy continues to progress. Last spring, we announced the Heartland pipeline and the TC terminals project. This initiative includes a 200 kilometer crude oil pipeline connecting the Edmonton region to facilities in Hardisty, along with an oil storage terminal in the Heartland industrial area just north of Edmonton. The pipeline would transport up to 900,000 barrels per day and up to 1.9 million barrels of crude oil could be stored at the terminal. Together these projects have a combined cost of about CAD900 million and are expected to be operational during the second half of 2015.

On May 30, we filed a permit or filed a permit application for the terminal and filed an application for the pipeline on October 24. In addition, we had some very positive news from Suncor last week, with the announcement the Fort Hills oil mining project is proceeding. It is expected to begin service -- it is expected to begin producing oil as early as 2017. Our Northern Courier pipeline is expected to be completed in 2017 and will transport crude oil from the Fort Hills mine site to Suncor's tank facilities north of Fort McMurray.

Moving now to natural gas. In September, we reached a settlement with our natural gas distribution companies in Ontario and Quebec. The settlement will allow TransCanada to provide customers with the flexibility of source gas from various locations, while ensuring the Mainline tools are set at levels that recover the cost of providing that flexibility. The settlement allows for the expansion of the Eastern portion of our system to meet the changing needs of Ontario and Quebec. We expect to file an application for approval of the settlement with the National Energy Board by the end of 2013. That settlement has an implementation date of January 1, 2015.

Finally, with respect to the Mainline, as of September 30, an additional 1.3 billion cubic feet a day of firm contracts have been signed originating at Empress since the implementation of the Tolls decision which took place on July 1 of 2013. Again, this highlights the importance of that infrastructure to the North American marketplace. Moving to our NGTL system, we continue to expand the network of pipe to gather more gas. CAD700 million of new facilities have become operational so far in 2013. We also have NEB approval to construct another CAD300 million of facilities.

In addition, in August, we signed agreements with Progress Energy for 2 Bcf a day of firm natural gas contracts that will underpin a major NGTL expansion, which is the North Montney pipeline extension. That CAD1.7 billion project will connect to a new delivery point, which is the Prince Rupert gas transmission pipeline, which will provide natural gas to the proposed Pacific Northwest LNG export facility on the West Coast of British Columbia. Volumes on the North Montney extension will ramp up between 2016 and 2019 to a total volume of 2 Bcf a day.

Delivery volumes on the Prince Rupert project are expected to be in the range of 2.1 billion cubic feet per day starting in June 20, 2019. We are also in discussions with other parties that are interested in signing contracts to ship gas on the North Montney extension. We expect to file an application for that CAD1.7 billion project in the fourth quarter of this year. Also in August, we took an important step when we reached a settlement with our NGTL system shippers.

The agreement will bring cost and rate certainty to the NGTL system through 2014 and represents an acceptable balance of interest between NGTL and its stakeholders. The National Energy Board approved the NGTL settlement and the final 2013 rates just this past Friday. Moving to Mexico, construction at the Tamazunchale extension is progressing. First quarter of 2014 continues to be our targeted in-service date. The Topolobampo and Mazatlan natural gas projects continue advance with engineering and permitting activities well underway. We still expect these two projects to be operational in 2016.

I'll now make a couple comments on the energy side of our business. In Alberta, Unit-1 at Sundance-A returned to service in September. Unit-2 became operational in October. As you may recall, TransAlta shutdown both of those units in 2010, but was ordered by an arbitration panel in 2012 to rebuild the units. Combined Units 1 and 2 are capable of generating 560 megawatts of power. In late September, we acquired two additional solar facilities in Ontario. Built by Canadian Solar Solutions, these latest acquisitions follow a July announcement when we told you that we had acquired the first of nine solar plants that we have planned to purchase.

The combined capacity of the nine projects is about 86 megawatts and will cost approximately CAD470 million. We anticipate the remaining six projects will come into service by the end of 2014. They will complement TransCanada's existing operations in Ontario. The renewable energy produced from these projects will be sold to the Ontario Power Authority, under a 20-year power purchase agreement. Today, one-third of the power that we provide in North America comes from carbon free sources. TransCanada has invested over CAD5 billion in emission free energy, including having the largest wind farm in New England, Hydro facilities in the US northeast, our solar investments and Canada's largest wind farm in Quebec. In addition to our interest in Bruce, which is now operating, as I said all 8-units for the first time in over two decades.

So to briefly recap, our assets did perform well. We had a very strong quarter highlighted by comparable earnings being up 26% compared to the same period last year and cash flow being a record CAD1 billion, up 21% over last year. Our portfolio projects under development continues to grow. Today, we have CAD38 billion of projects in various stages of development, providing visible growth for our shareholders for many years to come. In August, we officially announced the largest project in TransCanada's history. The 1.1 million barrel per day crude oil pipeline, Energy East, which is underpinned as I said with firm binding contracts for over 900,000 barrels a day.

This will allow Canada to replace imported foreign oil with Canadian oil in its Eastern refineries and provide significant economic tax and job opportunities right across this country. As I said, all of our project that we've announced, are underpinned by long-term contracts, giving us the confidence that they will generate predictable and sustained growth in earnings, cash flow and dividends. Growing shareholder value for our shareholders for decades to come. So I'll now turn the call over to Don who will provide additional details on our third quarter financial results. Don?

Thanks, Russ. Good morning, everyone. I'd like to begin today by highlighting a few key messages. First, all three business segments once again contributed very solid results in the quarter. Second, the positive momentum that began in the second quarter continued in the third with earnings growth as a result of Bruce Power operating as a full 8-unit site, a constructive power market in Alberta, the capacity market in New York and a higher Canadian Mainline return on equity. Furthermore, this momentum is expected to continue with the return of Sundance-A, the US Gulf Coast project commencing operations, the acquisition of the remaining Ontario solar projects and completion of the Tamazunchale extension in 2014.

Third, as Russ highlighted earlier, we continue to advance the our balance of our CAD38 billion portfolio of high-quality long life energy infrastructure growth opportunities. All of these projects are underpinned by long-term contracts or cost of service business models and are expected to continue -- to contribute to significant growth in earnings, cash flow and dividends over the remainder of the decade. Finally, we continue to be well-positioned to fund our current capital program. The CAD4.7 billion of capital that we've raised to date in 2013 on attractive terms is clear evidence of our ability to access varying sources of capital in order to finance our growth plan.

Now, moving to our consolidated results shown on the next slide. Comparable earnings in the third quarter of CAD447 million or CAD0.63 per share increased CAD98 million or CAD0.13 per share compared to the same period in 2012. The 26% increase in comparable earnings per share was primarily due to positive equity income contributions from all 8-units at Bruce Power, higher earnings from Western Power due to lower PPA costs, increased utilization of the Sundance-B PPA and the return to service the Sundance-A Unit-1, higher capacity prices in New York, increased generation volumes that are US Hydro facilities, and a higher allowed return on equity for the Canadian Mainline, which was partially offset by lower contributions from the US natural gas pipelines, reduced earnings from our unregulated natural gas storage business and higher comparable income taxes due to higher pretax earnings.

Turning to our business segment results at the EBITDA level. Our natural gas pipelines business generated comparable EBITDA of CAD684 million in the third quarter 2013, compared to CAD660 million for the same period last year. Canadian gas pipeline's EBITDA of CAD519 million increased CAD42 million compared to the same period last year. The improved results were primarily due to a higher allowed return on equity of 11.5% for the Canadian Mainline and a larger NGTL system average investment base as a result of ongoing expansions. Results for NGTL in the third quarter 2013 continued to reflect the last approved ROE of 9.7%. On November 1, the NEB approved our 2013 - 2014 settlements with shippers as filed.

As a result, our fourth quarter results will include a positive CAD8 million retroactive after-tax earnings adjustment to January 1, 2013. The adjustment reflects an increase in the allowed return on equity to 10.1% and a higher comp as a depreciation rate. It does not include any adjustment related to the fixed OM&A component of the settlement. Partially offsetting growth in Canadian gas pipelines was a CAD18 million decline in EBITDA at US natural gas pipelines.

Contributions from GTN and Bison were lower due to the reduction in our ownership interests from 75% to 30% affective July 1 following their partial sale of the TC Pipelines LP. Great Lakes realized reduced revenues due to lower rates and uncontracted capacity, while ANR experienced higher costs related to services provided by other pipelines, as well as lower revenues. Overall weakness in certain US pipelines is expected to continue. We are focusing on reducing costs to minimize the impact.

Turning to oil pipelines, Keystone generated CAD193 million of EBITDA in the third quarter. The CAD13 million year-over-year increase was primarily a result of higher contracted volumes. In energy, comparable EBITDA was CAD410 million in the third quarter compared to CAD267 million for the same period last year. The CAD143 million increase was a result of the combination of positive factors across our Canadian and US power businesses. Western Power's EBITDA increased CAD25 million in the third quarter 2013 primarily due to lower PPA costs, increased utilization of the Sundance-B PPA and the return to service of Unit-1 at Sundance in early September. Sundance-A Unit-2 returned to service in early October, which will allow us to recommence realizing the associated generation and related revenues under the PPA in the fourth quarter.

Turning now to Bruce Power, for the first time in two decades Bruce Power operated as a full 8-unit site for a full quarter with the return of Unit-4 from its life extension outage in April 2013. Equity income increased CAD101 million compared to the third quarter of 2012 reflecting the restart of Units 1 and 2, increased volumes from Unit-4 and the recognition of lower lease expense at Bruce-B. A similar lease expense reduction was recognized in the second quarter of 2013. No further maintenance outages are planned at Bruce for the remainder of 2013.

US Power EBITDA increased CAD29 million in the third quarter compared to the same period last year. The increase was primarily due to higher realized capacity prices in New York and higher generation volumes at the US Hydro facilities, partially offset by lower sales volumes to wholesale, commercial and industrial customers and lower generation at Ravenswood. Finally, natural gas storage results decreased CAD8 million in the quarter due to lower realized storage spreads partially offset by the acquisition of the remaining 40% interest in CrossAlta in December 2012.

Now, turning to the other income statement items on Slide 25. Comparable interest expense in the third quarter was CAD235 million, compared to CAD249 million in the same period last year. The CAD14 million decrease was principally due to higher capitalized interest, as well as Canadian and US dollar debt maturities, partially offset by interest on recent debt issues and higher foreign exchange on interest expense related to US dollar debt. In the third quarter, CAD80 million of interest was capitalized to assets under construction compared to CAD74 million for the same period in 2012. This increase reflects higher capitalized interest for the Gulf Coast project and Mexican projects, partially offset by lower capitalized interest related to the restart of the Bruce-A units.

Comparable interest income and other decreased CAD6 million due to realized losses in 2013 compared to gains in 2012 on derivatives used to manage the Company's net exposure to foreign exchange fluctuations on US dollar income. In combination with US dollar denominated interest expense, this hedging program largely counterbalances the currency impact of translating US dollar pipeline and energy income reported in the business segments. Comparable income taxes for third quarter 2013 increased CAD49 million compared to the same period last year, due to higher pretax earnings, combined with changes in the proportion of income earned in higher tax jurisdictions.

Now moving on to cash flow and investing activities on Slide 26. Cash flow was very strong in the quarter primarily due to higher earnings in the period. It is noteworthy that funds generated from operations exceeded CAD1 billion in the quarter for the first time and represents a 21% increase over the same period last year. Turning to investing activities, capital expenditures were CAD992 million in the third quarter, driven primarily by the Gulf Coast project, ongoing expansion of the NGTL system and construction of our Mexican pipeline projects.

Equity investments decreased CAD114 million year-over-year due to lower capital spending at Bruce Power. Acquisitions of CAD99 million in the quarter reflect the purchase of the second and third Ontario solar projects, which closed at the end of September. The acquisition of the six remaining projects is expected in stages throughout late 2013 and 2014, as they are satisfactorily completed and brought online.

Now, turning to Slide 27, our liquidity and access to capital markets remains solid. At the end of the third quarter, our consolidated capital structure consisted of 41% common equity, 5% preferred shares, 2% Junior subordinated notes and 52% debt net of cash. At September 30, we had CAD645 million of cash on hand, along with over CAD4 billion of committed and undrawn revolving bank lines with our high quality bank group. Our commercial paper programs in the US and Canada are well supported and provide flexible and very attractive sources of short-term funds.

In early July, we completed the sale of a 45% interest in each of GTN and Bison, for $1.05 billion, which included CAD146 million of GTN related debt to our master limited partnership TC Pipelines. TC Pipelines successfully financed the transaction through a public offering of common units and a debt placement. Aside from maintaining our GP interest, we did not participate in the equity offering. As such, our ownership interest in the partnership decreased from 33.3% to 28.9%. This asset drop down is a clear demonstration of one of the many financing options available to us, as we progress our unprecedented growth portfolio.

We also issued CAD2.5 billion of term debt in three offerings since July at compelling rates. Specifically, in July, we issued our first LIBOR-based floating rate notes, raising $500 million in 3-year funding at an initial interest rate of 0.95%. Also in July, in Canada, would we placed CAD450 million and CAD300 million of medium term notes for terms of 10- and 30-years, bearing interest at 3.69% and 4.55% respectively. Finally, in October, we issued $1.25 billion in Senior notes split evenly between 10- and 30-year maturities, bearing interest at 3.75% and 5.0% respectively.

Year-to-date, we've now raised CAD4.75 billion on attractive terms through an array of funding products to a diverse investor base. We also redeemed at par all of the outstanding 5.6% Series U preferred shares in October. The total face value of the outstanding shares was CAD200 million. They carried, in aggregate, CAD11 million in annualized dividends. We have completed our financing requirements for 2013, but will be opportunistic in sourcing additional capital at what remain attractive funding levels. Looking forward, we remain well-positioned to finance our capital program with funds generated from operations, new Senior debt, as well as subordinated capital in the form of additional preferred shares, hybrid securities and portfolio management, which may include further LP drop downs.

In closing, TransCanada produced another strong quarter. Year-to-date comparable earnings per share and funds generated from operations are up 15% and 18% respectively compared to 2012. Going forward, the return of Sundance-A, the addition of new capital projects in late 2013 and into 2014 including the Gulf Coast project, the Tamazunchale extension, the acquisition of the remaining Ontario solar projects and ongoing expansions of the NGTL system, along with a higher allowed NGTL system return on equity are expected to continue to positively impact future earnings. This is expected to be partially offset by higher interest expense due to reduced capitalization as projects come into service.

Finally, we continue to advance the balance of our program of large-scale commercially secured capital projects, which now stands at CAD38 billion with the recent addition of Energy East. These projects, which are targeted for completion between 2015 and the end of the decade include Keystone XL, two natural gas pipelines to Canada's West Coast, two gas pipeline projects in Mexico, several oil pipeline and terminal projects in Alberta, and the Napanee generating station in Ontario. Each of these are underpinned by long-term contracts with strong counter-parties. We remain well-positioned to fund the balance of the program. This large capital program is expected to generate significant growth in earnings, cash flow and dividends for our shareholders over the remainder the decade. So that's the end of my prepared remarks. I'll now turn the call back over to David for the Q&A.

Thanks, Don. Just a reminder before I turn it over to the conference coordinator, we will take questions from the financial community first. Once we've completed that, we'll then turn it over to the media. With that, I'll turn it back to the conference coordinator.

(Operator Instructions)

Paul Lechem, CIBC.

With Fort Hills getting the go-ahead here, obviously, Northern Courier's being derisked. So I was just wondering where Grand Rapids stands with the uncertainty around the Dover project? If that has any impact on the timing and the certainty of that project?

No, I don't think so. The project is anchored by long-term take or pay commitments when the project is available for service. We think we have a pretty superior competitive position in that West Athabasca region.

But to be clear though, if Dover doesn't get approved to move ahead, does that mean that part of Grand Rapids doesn't get built?

We will wait and see. What I know is that we have a take or pay deal. It is not dependent on that regulatory issue.

Okay. On the Mainline, you said you were going to file the first half of 2014 for the papers for Energy East. Just wondering what that means to the Mainline, the gas Mainline totals. Does that kick off a new rate case? If so, what should we expect out of that rate case? Is it a full-blown hearing? Could it change the methodology, yet again? What does that mean?

It's Karl speaking. Well it really depends, I guess. Right now, we've just finished the settlement with some of our Eastern customers. We are going to be filing that settlement before the end of the year, here. If the Board approves that settlement, as we expect it will, I don't think we will need another gas rate case for the Energy East project. Now we will need -- for the gas, we will need a regulatory hearing on transferring the assets out. But I think the tolling of the pipeline will be fine if we get the settlement -- if we get the settlement approved.

Just to be clear, Paul, the -- we need to have an application essentially to take the gas pipeline out of gas reserves and put it into oil service. That will have an impact on the rate base on the gas side. It is our expectation that impact will positively impact rates for gas consumers. As Karl said, one of the benefits, I think, of the settlement that we've just come to is it provides data framework for adding additional capital if necessary to the system to provide access to alternative supplies that our Eastern customers want to get access to. So I think it will be combined together, but I suspect that at the end of the day, it will have a positive impact on rates and costs for gas consumers.

I've got you. Thank you very much.

Linda Ezergailis, TD Securities.

Just a follow-up question with respect to your Mainline settlement. How are your discussions going with other stakeholders that are non-LDCs? What are the main elements that would change for them? What gives you the confidence that the regulator will substantially approved that settlement?

Well first of all, we've just finished the legal -- I guess settlement agreement with the LDCs. We filed that -- we finished that last week. We filed it with the OEB for a LDC hearing on the OEB. So, that document has really only been out for less than a week right now. So we have talked with many of our other stakeholders on the system. I think it is fair to say everybody was waiting on -- until the final document was received with all the tolls before they gave us any substantial feedback on that.

The reality is that this settlement does increase some of the tolls on the system. It does put the Eastern triangle back onto cost of service. That will increase the tolls on that system. So, we will have some stakeholders that will not be happy with that result. But what I can say is, we believe we can get a substantial majority of the rate -- the stakeholders that pay rates on the system. Upwards -- the LDCs alone are probably 70% to 75% of the rates that we've -- of the revenue that we see with the systems. So we will be well in excess of that when we go to be Board with the settlement.

And cap? Have they provided any feedback? Or how will things change for producers?

I think cap as well has been waiting for the final document to come out. They want to take a look at the impacts on rates and some of the final -- the terms and conditions of the document. So, although we've talked with them several times, I think we will wait and let them absorb the document and then go back and chat with them again.

Okay, thank you. Just a quick follow-up question. Your business development expenses in your oil pipelines increased quite a bit year-over-year. Are you capitalizing Energy East? Is that substantially Energy East? Or what else are you working on there?

It is Glenn here. Yes, Energy East costs are being capitalized right now. As far as the oil, BD expenses don't have a specific reason other than just increased activity in the segment.

Would it be more on the export side or the regional side?

Linda, it is Alex. It's really all of the above. But lately, we've been pretty active domestically in Canada, but also looking at opportunities in the US. So it is really just -- we are seeing a lot of BD opportunities on the liquids side.

Great, thank you.

Linda, I guess just I would augment Alex's comments with, once we've got this backbone infrastructure in place, the volume of new opportunities coming to us has increased. We are responding to those as quickly as we can. We always thought that once you have the backbone in place, opportunities will come. That is certainly what we are finding is occurring with the growth in production on both sides of the border.

Great, thank you.

Juan Plessis, Canaccord Genuity.

Congratulations on a strong quarter. You've contracted an additional 1.3 Bcf per day on the Mainline since July 1. What is the total contracted volume you have now on the Mainline? Based on what you are seeing now, what amount if any of further contracts do you expect to attract?

Well, the 1.3 Bcf represented just a little bit over doubling of our Western receipts on the Mainline. So, we're, right now as of November 1, we are moving about 2.5 Bcf in that area. Are there more contracts to be had? Yes, but I think for the bulk of the firm load that's on our system, we now have under firm contracts. So there is probably some more contracts to be had, but I wouldn't expect anything real material for the next year.

Okay, thanks for that. Alex, I wonder if you can update us on your Alberta hedged volumes and average prices for the rest of the year and maybe into 2014?

We're stepping back a bit from giving that kind of guidance. There are certain parties that are -- have indicated -- or have some concerns about the level of information could potentially be used in competitive manners. So, we are being a little bit more coy on that than we have in the past. What I would sort of directionally say is, we are -- we still have a significant merchant component, but we have been able to execute a fair amount of forward sales in the Alberta business for next year.

Okay, thank you very much.

Carl Kirst, BMO Capital Markets.

Nice quarter as well. Maybe head back to Energy East for a second. Don't want to read too much into anything, but I think previously we're thinking about a NEB filing around March, now we're talking first half of 2014. I just want to make sure, are there any gating factors that we should be, I guess, we should be looking at? Maybe I'll stop there and ask that as the first one.

Sure, Carl, it's Alex. I think more than anything, is I think you heard us talk about, in the media, we were pleasantly surprised with the uptake on our open season on Energy East and that resulted us -- with us right out of the gate up-sizing the project. We're now going to have two marine terminals. So, that slight modification in language you saw with respect to permit filing is really just the fact that we have some more facilities we have to deal with. It is very important that we get this upfront work done correctly and that we get a lot of work done with our stakeholders before we file. So it is really just a recognition of the new facilities and just want to make sure we get it done right.

Okay, thank you. Then just as a follow-up and I just want to make sure I'm understanding this. So, when the NEB filing is made for Energy East, it is going to be all-inclusive with the asset transfer from the Mainline. I guess the amount of that transfer is still something that is evolving, shall we say. So, when that happens, is the goal to wrap that up with having both utilities and cap on board at that time? I just want make sure I've got a better sense of how we should think about that.

Carl, I will take a shot at it. It sort of crosses both the oil and the gas lines. It is our intent to put forward a proposal that is in the best interest of all of those parties on both the oil and the gas side. I think that under the parameters that we've discussed to date and the amount of the transfer, it's our current thinking that we can provide benefits to all of those customers. We want to make sure that customers on both sides are able to get access to the capacity that they want and need and are willing to contract for. So, it would be our intent to try and pull it all together. Hopefully, when we file, we will have the support of all of those parties.

Great. Thanks, Russ. Thanks, guys.

Matthew Akman, Scotiabank.

First on Ontario Power, Alex, can you please give us an update on Napanee? Given some of the issues around the auditor's report on Oakville, is there any hitches there or environmental issues? Or is that one now still full-steam ahead?

From our -- first, I'll talk about where we are on the permitting side. Then I'll give you my thoughts on that AG's report. But, we are well advanced in our permitting process. We've started our open houses. We are doing the required field studies. We imagine, we should have our permits mid-2014. Then give it a 30-month, probably give or take, construction period, just giving you timing for in-service. With respect to the AG's report, that's a process that is ongoing.

We gave some very limited testimony in that process. We certainly -- with regard to suggestions that TransCanada was able to benefit from Napanee, I think the only comment I would make is, this project, when it was originally going to be the Oakville project, we actually would be in service today. So we have four year delay. I don't think anybody has thought about the material implications of that four year delay. This project to us looks like, materially identical returns that we were expecting from Oakville.

Okay. Thanks. Staying with Ontario Power. Bruce, obviously had a great quarter. It's great all the units are in service. I guess the next topic is going to turn to refurbishment of B. The province is talking about updating an energy plan in the coming months here and not building the nuclear but refurbishing existing. I'm just wondering if they are in consultation with you guys on that, because obviously, especially if we're not building new nuclear, then existing refurbishment has to be a very important part of their plan.

Yes. I think that's clearly the case. I think that -- they are going to come out with this new energy -- long-term energy plan, probably, I think, sometime this month or certainly by the end of the year. They've announced that they are abandoning new build -- the government has announced they are abandoning new build at Darlington. So I think that even puts more impetus on the refurbishment of the existing reactors. I think we've shown, with the Unit-1 and Unit-2 refurbishment -- although we had challenges, we've also learned a lot. Even with all of those challenges, those reactors are operating very well. They are delivering power at a very competitive rate with no GHG emissions. So I think there is still a lot of work to go on refurbishment discussions, but I think we are -- certainly at this point, I think it looks like there is great opportunity to work with the government, the OPA and stakeholders to go forward on those refurbishments.

Okay. Great. Thanks, guys. Those are my questions.

Andrew Kuske, Credit Suisse.

Spectra made some comments, I think it was yesterday or very recently about possibly looking to expand the Express/Platte system. Obviously that would include a Presidential Permit, that would be necessary. Could you just give us your thoughts on the process you've been through to date. Does that really set the new standard for any kind of Presidential Permit application process or even an amendment that Enbridge has with Alberta Clipper?

I guess my thoughts -- Russ may want to jump in on this, but I think what we've gone through on the Keystone XL Presidential Permit process is certainly not what we would have expected prior to that application, for a standard type Presidential Permit. I think all that being said, all of the issues that have made Keystone XL contentious with the opposition would be equally applicable to both of those projects you identified. I think it would be pretty naive to assume that any future project, certainly in the near future, would be going through a significantly lower hurdle in terms of the Presidential Permit process.

Okay, that is helpful. Then if I just -- may ask a second question. It just relates to Mexico. If you could just give us your interest in Mexico? We've seen some awards that have been made recently. You weren't involved in those awards. Just what is your appetite for further development in Mexico on a longer term basis?

Yes. We still consider Mexico to be a very key and core area for us. The awards that you saw was from the Los Ramones project in Mexico. We chose not to bid on that project. There were parts of that project -- commitments that we're making that we just weren't comfortable with. It just didn't fit what we're doing down there. So we didn't -- we chose not to bid on that particular project. But we are still working diligently in the area on -- not only on our existing projects, but on other new projects that are going to be coming up.

Robert Kwan, RBC Capital Markets.

Just with the additional FT contract you signed and anything you've done on an STFT for the Mainline. Just wondering what your cash ROE expectations are? Then just second, on the Mainline, with that LDC settlement, you've talked a lot about the Eastern triangle, but just wondering if there is any impact on the long-haul part of the system?

Okay. Well first let's start with what we have contracted for. So, the FT that we've contracted for and our forecast of other discretionary sales that we are going to make until the end of the year -- we are going to be selling some uninterruptible and some STFT as well, for the end of the year. We are predicting that we will earn our revenue requirement this year, which is about CAD1.5 billion. So we should be -- pretty close to that number for a flow revenue recovery in 2013.

The ROE on our system is set at 11.5% on 40%. That doesn't change with the revenue that we collect. But what does change is that we're going to come out of the year with very little deferrals if any in the TSA account, the Toll Stabilization Account. So it looks pretty good for this year and actually, it looks pretty good for next year for recovery of our rate case. The second question, the second part of that question you had was? Could you refresh my memory on your second question?

Yes. Just on the LDC settlement. If there's any impact on the long-haul part of the system?

Yes. What's going to happen with the long-haul part of the system -- so, in essence, the settlement that we've negotiated really has two main objectives. First, it separates the Eastern triangle part of our system out and tolls that independently from the rest of the system. It is tolled on a cost of service basis. So what that does for the LDCs is that allows them -- that allows us to make investments in that system. It allows us to roll-in the investments. It allows us to get recovery -- to have a line of sight on getting the recovery on those investments. It also allows expansion on the system. The second part -- the second objective of the settlement really is to allow the LDCs to move from long-haul to short-haul. One of the problems we had with the NEB decision with the fixed tolls was that any time somebody moved from long-haul to short-haul, we would have a revenue deficit. Now that we are totally on a cost of service basis, there will be no revenue deficit.

We can cooperate with that movement. So, what's going to happen with long-haul? Long-haul is still going to be tolled on the NEB fixed-price toll. But they will be paying as will the Eastern triangle, they will be paying a slight premium to that, for the transition charge. But what we've done with that is the LDCs have guaranteed a 13% of their requirements to stay on long-haul until 2020. So you should see the long-haul totals, they'll maybe go up somewhere between 15% and 20% over the six years of this settlement. But they should remain pretty stable during that period of time.

Great. Thanks, Karl. Just last question here, probably for Alex. New York Zone J capacity prices for this month were -- actually spot price cleared nicely at CAD10 a kilowatt month. Just wondering what you thought about that? What your expectations are through the winter? We basically doubled year-over-year.

Yes. I think from our perspective, we've obviously had a reasonably nice pickup in New York capacity prices. Yes, as usual, in the New York market, there are some puts and takes. I think a lot of the reason for that trend up was that the in-city required capacity moved up by about 3%, I think it moved up to about 86%, which had a positive -- I think, was largely related to that positive move up. We do expect that Hudson Cable project to get -- to be coming in and getting credit for capacity here, over the next little while. But on the same side -- or on the other side of that, we have the new demand curve reset process, which we would think all things being equal will probably be putting an upward pressure on the capacity payments. So you put all of that together -- I look at an overall capacity payment for 2014,, probably not that different from what we experienced in 2013.

Okay, that is great. Thank you.

Steven Paget, First Energy.

The contracts on the Mainline, Karl, how much of the revenue requirement is being met now through long-term? How much revenue do you need from short-term contract?

I would say right now for 2013 around the 80% is going to be collected from the FT contracts and about 20% from short-term. That would be a little higher next year because we've sold a little bit more FT for next year. So it'll be maybe in the 85% range is recovered from the FT contracts.

Thank you. Just following-up on Mexico. Could you please comment on opportunities in Mexico? What scale of investments -- new investment might be announced in the next three years overall rather than just TransCanada?

It is hard for me to put the scale for what Mexico's planning, because they've been changing their plan over the last few months. What I can say with it is Mexico is trying to interconnect itself more thoroughly to the North American grid. The projects that we've done and the projects that they've got so far are the start of that. I would see -- I would guess that the country as a whole, aside from the Los Ramones project that we just talked about from Pemex, but would suggest with the country as a whole, we could see a doubling of what they offered the last two years. So that would be easy to see. When the timing of that comes is uncertain right now. We are in constant discussions, as you can imagine, with them on their new projects. But there is a bit of a process to be had there. So it's very difficult for us to guess when those projects would come up for bid.

Thank you, Karl. Those are my questions.

Pierre Lacroix, Desjardins.

Alex, you mentioned that you had some business development opportunities on the oil pipelines in the US. Could you comment a bit more about the opportunities that you are seeing there?

It's pretty premature for that. We like to really save comments when we have something material to disclose. But we're looking at opportunities around the Bakken and some opportunities around the Gulf Coast. But as I said, it is pretty early days for us to be talking more definitively about it.

Any thing -- any opportunities with the [Tucson] version of natural gas pipe in the US?

I think what I would say is, just generically, TransCanada is always looking at maximizing the value of its assets. With this incredible gas pipeline grid that we presently operate, it just -- it does it lend itself to looking at oil conversion opportunities. A lot of those pipes are potentially located in attractive opportunities for that. It is always easiest to look at BD opportunities in your own backyard. So we are taking a very hard look at that right now.

Thank you.

Peter DeBaz, Citadel.

My question is actually regarding the Gulf Coast pipeline project. Given the 95% of the work is done on the lines, when do you expect the line to start filling with oil? How long do you think that will take?

We are -- as Russ said, we are very close to completion. We would expect that we will be calling for first oil here probably in as early as a few weeks.

A few weeks? Okay. So that's basically pushing the line -- pushing the oil down the line?

Yes. Putting in place line fill, yes.

Okay. I guess as a follow-up, what part of the 700,000 barrels a day, you think is contracted volumes on the pipe? In line with that, what flows do you expect to see once the line fill is complete?

Like -- most of these projects, they take a little while to get up to full capacity. It does have a capacity of 700,000 barrels a day, an ultimate capacity of 830,000 barrels a day, if we add additional pump stations. I would guess in 2014, we are probably looking at something in the 550,000 barrel a day range. The pretty significant majority of that would be contracts.

Okay. I guess just the last one on that is, can we expect to see the volumes actually reaching Port Arthur by end of this year? Or that will be more of an early 2014 phenomenon I think, given --

No, we intend -- we should have first oil hitting Port Arthur before the end of the year.

Okay. Lastly on the committed volumes, what tariff do you expect to get on those?

I don't think we -- we're not disclosing that information right now.

Okay. Thank you. Those are all my questions.

Carl Kirst, BMO Capital Markets.

I had just one quick follow-up please on the US pipes. Don, I think you had even mentioned in your remarks that we expect a challenge to be ongoing. At the same token, we have signed now 350 million on ANR at firm rates. We now have a settlement on Great Lakes. So I guess what my question is, of those two developments, do you see that basing out the US pipeline earnings here, 2013 to 2014? Do you still see more erosion possible? Or is it even possible to break out what the actual impact of those two -- the settlement and the new ANR contracts would be?

Yes, it's a good question. The question is, have we hit bottom? Are we starting to move up here? I guess I'll talk about the ANR first. The Lebanon contracts, Lebanon lateral contracts, we got 350 million a day, I think a very, very positive development for that pipeline. I've talked about that play line several times, being a very diverse pipeline with lots of market and lots of supply on it. I think accessing Utica and Marcellus is very positive for that. We expect that to grow over time. You have to remember those volumes will come on the system over the next year, so they're not coming in right away. So I'm still forecasting a pretty difficult year next year for ANR. Their transportation spreads are thin. The storage spreads are very low. Then -- we have some big bills for transportations of others on that pipeline.

So, it's still -- have we hit bottom next year? Maybe. I do see some good signs to it, but it's not going to be -- it's not going to turn around that quickly. On Great Lakes, you are right. We did get a settlement, a 21% increase. But you have to remember, that 21% increase is on our default rate. We don't have a lot of customers anymore at the default rate, so it's pretty modest revenue improvement. I think the positive -- the positive part of the Great Lakes is now that we have the Mainline settlement in place, once we get that approved, I think we will have a certainty in the market of what it costs to move gas into that system. We think that is directionally positive. But again, I think we're in for next year, another difficult year quite frankly, because I think [the] transportation spreads are just poor. Poor for the foreseeable future on that line.

Appreciate the color. Just maybe, on ANR, are you moving much up from the Gulf? Or is it primarily now just regional and the Midwest?

Most of the volumes on that system now come from the Mid-Continent shale plays, so it's got a good diverse supply base. When that system was originally built, it was Gulf Coast natural gas into it. But right now, Gulf Coast is a very small percentage of the gas in that system.

Excellent. Thanks so much, guys.

(Operator Instructions)

Kelly Cryderman, the Globe and Mail.

This message is for Mr Girling. I'm just wondering if you learned anything more about the timelines for Keystone XL during your recent trip to Washington?

No, I think the process is as it's been for months. We are waiting for the final environmental impact statement to be completed and issued. It would be our hope that is in the near-term here. Then once we receive that, I believe that there is up to a 90-day natural interest determination period and probably it'll be between 15 and 30 days to complete the record to get to a final Presidential Permit. There was no update on when that FEIS would come out in my meetings in Washington last week.

But given everything you just laid out there, we are talking almost mid-2014 then, at the earliest?

Again, those processes -- the timeframe of those processes are determined by the State Department. As I said, the timeframe to get to a FEIS, in my view, could be relatively short. We've been through 15,000 pages of review. There is nothing left to review. We could get to that relatively quickly. As I said, the natural interest determination is up to 90 days. It doesn't necessarily have to take that long, but we are not in control of that process. So, it's sometime in between now and the end of those dates. I have given up trying to predict where in there it might fall.

Thank you.

Mark Petrone, Sun Media.

The idea that environmental activists have hijacked the process -- you've used some strong language in that regard. Do you have any indication as far as Keystone is concerned that, given the past and the past behavior of this current administration that they will eventually green light the project, given their intransigence so far?

This is -- for me this isn't a political comment, the original Keystone project took about 21 months to approve. All of the same issues were raised in that process. Similarly, the Enbridge Clipper project took about 27 months. We are now in 60 months -- greater than 60 months in this process. So, I guess my view would be is that based on past history, which is decades of free trade of energy between these two countries, the importance of energy trade of free trade agreements and the establishment of about 3 million barrels a day that moves across the border today of heavy oil -- based on that and the US need for oil, my view is we will get approval.

Really nothing has changed in that, the US needs crude oil in excess of its own production. Canada produces oil in excess of its own consumption. The marriage of those two things make sense historically. It make sense today. It will make sense for many decades into the future. So, I don't actually see how that has changed. Those are the fundamentals, which will, I hope drive the decision for the Keystone project.

Yet you have an administration that in spite of everything that you've said and the rationale that you've given, to green light this project, it hasn't happened up to this point. So, the question is, do you have any hope whatsoever that this administration will come to the same view that you have had regarding Keystone and eventually green light this project?

Yes, I've got every confidence that we will get there. We have -- the State Department has issued four environmental impact statements. In all four of those, they have come to the conclusions that outline -- A, that the project is necessary; that it has limited environmental impact on the resources and property along the route; and it will have no material impact on GHG emissions. So, we have seen the administration come to those conclusions four times already. I would expect that the fifth time, when they issue the final environmental impact statement, it will come to same the conclusions because there is no way to come to any other conclusions, except for those conclusions.

The pipeline does not increase consumption and therefore does not increase GHG admissions. It has met every other criteria. So, I fully expect that the administration will continue to process the data that they've accumulated and the comments -- the 1.5 million comments that they accumulated in the last comment period. They will get through that process. They will issue a FEIS. My belief is that will pave the way to a positive Presidential decision.

This last question, it has to do with the ongoing diplomatic efforts on the part of Canada to try and get this project green lighted. Have those efforts had any impact, in your view?

I believe that the support of the Canadian government with respect to a major industry that is a major driver of the Canadian economy is extremely important. Some of the questions that have been raised with respect to energy trade between the two countries and the questions that you raised have -- has any of that change? I think it is important for the Canadian government to voice its view that it's -- the importance of the production of energy in Canada to the economy is substantial. They have a desire to develop those resources.

They will develop them responsibly, but I think they want to make it clear that there's -- make no mistake that those resources will get develop. They will move to market. The preferred market is the US market. But they will also develop other markets along the way. So, I believe that those positions that the Canadian government has taken with respect to US and export markets are critical and continue to be important both for the projects like Keystone, but other projects that have been proposed by other proponents and our projects, which includes the Energy East project.

Thank you.

Edward Welsch, Bloomberg News.

I have a couple of questions on the Mainline. I was just wondering, now that you've got this additional 1.3 Bcf a day on the pipeline, is this enough basically in a nutshell to make this sustainable over the long-term? I believe it is still underutilized running at less than half capacity. So I'm just wondering if you could provide some guidance on that? Also, I'm wondering, the change in the short-term tolls that happened between July and September caused a big move in the natural gas market in Western Canada, AECO prices really dipped. I'm just wondering, what was the thinking when you decided to reverse some of those changes in September? Or you changed the structure? Was that in reaction to what was happening in the market? Or had you already achieved what you intended? Those are my questions.

Your first question with respect to sustainability of the Mainline. I think what we have always said is that the Mainline is a critical piece of North American gas infrastructure. The question was, how it was going to be tolled as opposed to how was going to be utilized? There is no question that with the advent of [no] production in our traditional markets zones, like Marcellus gas, it has had an impact on our long-haul volumes. That said, there is still is a requirement for base load volumes to move through that system. It's incredibly important during peaking times in those Eastern markets.

So we've seen our volumes reached 4, 5, 6 Bcf a day in those peak periods across the prairies. But at the same time the Eastern end of the system is full every day. So, the system is needed and will be needed for many decades to come. The settlement that we've put in place really just speak to, who will pay for the system? How those costs will be allocated over time. With respect to our tolling changes on July 1, we implemented the National Energy Board's new tolling structure that they had put in place for us. As a result, we moved our discretionary pricing to meet the market demands.

I don't believe that our tolling alone has the ability to move basis differentials across this country. But certainly, we moved to a place where we were trying to encourage our customers to use the system and to pay for the system in a way that met their long-term needs. What we determined in that process is that their long-term needs are best met -- for those group of customers that sign long term contracts by signing with us for a term period so that they had certainty. At the same time, we had certainty of revenue.

Okay. Thanks a lot for that. So I was just wondering -- Carl's comment that I believe he doesn't expect any more long-term contracts beyond the 2.5 that has already been reached. Why is that? Is just -- is that the maximum that you think you can get in the long-term contracts or --

I think I said that I'm expecting some extra long-term contracts, but I don't think we will see another 1.3 Bcf come on the system. There still is some opportunity to market it. But we will fill up the pipeline after this with the more seasonal volumes. Winter is coming, people are going to walk down the shorter-term -- the short-term firm or the interruptible service. So there is two basic types of services people do buy in the pipeline, they will buy the FT, the firm total service for their base needs, for their needs for their firm commitments. Then they will buy our interruptible and our short-term needs for their non-firm requirements, so to speak. So we'll still be marketing. We'll still be bringing volumes on that system. But the -- as I said I don't believe we'll bring another 1.3 Bcf into the system. But we will bring more FT into the system as time goes on.

Jeff Lewis, Financial Post.

Regarding the North Montney project, with the discussions you're having with parties interested in using that line, besides Progress Energy, would that involve upsizing the project beyond what's been proposed? Then I have a follow-up question.

I guess to answer that question is maybe. We haven't really concluded those discussions, yet. But the North Montney area of our system is -- there is many different producers in that area and many other LNG producers of LNG aspirations of that area. That is difficult to say right now how successful we will be with talking to the other producers, but there are other customers looking to get on that system. If they come with material volumes, yes, we might -have to upsize that part of the system.

Secondly, just as a follow-on, what are your guys thoughts around or have there been any discussions around perhaps consolidating some of the of the structure that is planned into the coast, saying gas line and the Prince Rupert transmission line?

I think that is up to the proponents of those projects, TransCanada I think offers a very beneficial service in that we can attach all of those projects to the liquidity of the NGTL system and that is very attractive to them. In terms of combining projects downstream, all of these different proponents have different time frames for both production and when they want to have their product available to market. That obviously makes it a little bit more complicated to bring these projects together. We are not aware of any projects that are being talked about being brought together, but there is some obvious logic that you could see in bringing some of these projects together if they could align themselves on timing and other issues.

Okay, thanks.

Thank you. There are no further questions registered at this time. I would like to turn your meeting back over to Mr Moneta.

Thanks very much. Thanks to all of you for participating today. We very much appreciate your interest in TransCanada. We look forward to talking to you again soon. Bye for now.

Thank you. The conference has now ended. You may disconnect your lines at this time. We thank you for your participation.